Relay Coordination (1)

8/11/2019 Relay Coordination (1)

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PRESENTATION ON

RELAY CO-ORDINATION

BY

Manoj Pandey


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OBJECTIVE

TO GIVE AN OVERVIEW OF SETTING ANDCO-ORDINATION OF PROTECTIVE

RELAYS IN AN INDUSTRIAL POWERSYSTEM.


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RELAY CO-ORDINATION

What is relay co-ordination ? Why it isrequired ?

Properties of Protection Scheme. Basic terms related to relay co-ordination. Steps in Relay Co-ordination. Typical relay setting & co-ordination

Example


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WHAT IS RELAY CO-ORDINATION

PROTECTION CO-ORDINATIONREFERS TO CO-ORDINATION OFPROTECTIVEEQUIPMENT SUCHTHAT DEVICECLOSEST TO FAULTIS OPERATED FIRST.


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WHY RELAY CO-ORDINATION ISREQUIRED?

IT IS REQUIRD TO ISOLATE ONLY THE FAULTYLINE WITHOUT AFFECTING OTHER LOAD

CONNECTED TO BUS. FOR MINIMIZING THE DAMAGE.


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PROPERTIES OF PROTECTION SCHEME

IT SHOULD SATISFY 3 S:

(1) SENSITYVITY : It refers to minimum operation current.(2) SELECTIVITY : It refers to discrimination.(3) SPEED : It refers to time of operation of the relay.


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Co-ordination in small power distribution Between SFU & MCCB

0

0

10

1,000

100,000

1 10 100 1000 1000

0

CURRENT IN AMPS

T I M E I N S E C

SFU125MCCB125


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0.001

0.1

10

1000

100000

1 10 100 1000 10000

CURRENTIN AMPS

T I M E I N

S E C O N D

SFU400

MCCB400


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Co-ordination in small power distribution Between MCB & MCCB

0.001

0.1

10

1000

100000

1 10 100 1000 10000

CURRENT IN AMPS

T I M E

I N S E C

MCCB125

MCB63


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0.01

0.1

1

10

100

1000

10000

1 10 100 1000 10000

MCCB630

SFU400


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Terms related to Protection co-ordination

Primary & back-up protection. Zones of protection. Selectivity. Pick-up. Plug Setting Multiplier (PSM). Time Setting multiplier (TSM). Primary Operating Current (POC).

Relay Operation Time. Co-ordination Margin.


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Relay co-ordination Basic termsPrimary & Backup protection

For fault at F1:R1 is PrimaryR2 is First Backup.

R3 is Second Backup. For fault at F2:R4 is PrimaryR5 is First Backup.


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Relay co-ordination Basic terms Zones of protection

Protection is arranged in zones,which would cover the powersystem completely leaving nopart unprotected. Zones ofprotection should overlap acrossthe circuit breaker being includedin both zones (Fig. A). Case A isnot always achieved,accommodation of CT being in

some cases only on one side (Fig.B). For fault at F busbarprotection would operate and tripC but may continues to be fedthrough the feeder.

Power system protection isusually engineered throughoverlapping zones. Theadvantage is positive discussionof faulty area / element. Thedisadvantage some times can bethat more breakers will be trippedthan the minimum necessary todisconnect the faulty element.


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Relay co-ordination Basic termsSelectivity

Discrimination by time Discrimination by current Discrimination by time & current-Both.


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Relay co-ordination Basic termsPick-up

Minimum value of input for which relay starttaking action:

For ABB make SPAJ 140C ___(0.5 2.5)In Steps of 0.1

It is related to sensitivity of the relay & donethrough plug setting on the relay.


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Relay co-ordination Basic terms Plug Setting Multiplier (PSM)

Relay characteristics is not drawn on actual current basis. Relaycharacteristic curve is a curve of PSM Vs operation time.


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Relay co-ordination Basic terms Time Setting Multiplier (TSM)

We Don t set desired relay operation time directly in seconds, butwe set them as Time Setting multiplier (TSM).

TSM = Desired Operation timeOperation time at TSM=1

Normal Range (0.05 1) in step of 0.01


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Relay co-ordination Basic termsRelay Operation time

Relay Operation time depends ontype of curve selected.

(50) DMT :- It has fixed current &Time settings.

Range (0.5 40) In; step 0.1 In.Time delay (0.04 300 sec);

step = 0.01 Sec.

(51) IDMT :- Relay Equation:Operation time = TMS x

(PSM) 1 As per IEC 60255

Application

NormalInv(NI)

0.14 0.02 MCC/PCCINCOMER

Very Inv(VI)

13.5 1.0 PrimaryOf TR

Extremeinv. (EI)

80 2 Breaker /Fuse Co-ordination (Spl.In case of EF)

Longtime Inv(LTI)

120 1 NGR


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Relay co-ordination Basic termsCo-ordination Margin

EMPIRICAL FORMULAS FOR CO-ORDINATION Fuse & Breaker

td = 0.4t + 0.15, wheretd = discrimination time

t = Fuse operation time0.15 = Relay operation time + safety margin0.4t = Relay ratio error

Breaker & Breakertd = 0.25t + 0.25

t = downstream relay operation time0.25 Down stream breaker tripping time + relay overshoot +

Safety Margin.


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STEPS IN RELAY SETTING & CO-ORDINATION Assumptions:-(1) Complete single line diagram is available(2) Short circuit calculation at each relay point is done.

THING TO REMEMBERRelay co-ordination for phase fault and earth fault is done separately.

ROAD MAP FOR CO-ORDINATIONSTART FROM THE BOTTOM MOST RELAY AND GO UPWARD.USE EMPIRICAL FORMULA.


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OVER CURRENT RELAY SETTING: RELAY R1(51)Plug setting multiplier (PSM)

Transformer Running load current I RL = 80% of transformer rating

=0.8 X 2749.3 = 2199 Amp. Highest Rated Motor = 132 kW Running Load of 132 kW motor I FL = 235 Amp. Starting current of 132 kW motor I ST = 7.83 X I FL = 1840 Amp

Considering Direct on line starting MethodPS = I RL - I FL + I ST = 2199 235 + 1840 = 1.27

CTR 3000Set PS = 1.3

Actual Primary Operating Current = PS x CTR = 1.3 x 3000 =3900 A

Plug Setting Multiplier = I fault = 33805 = 8.66POC 3900


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OVER CURRENT RELAY SETTING: RELAY R1(51)Time setting multiplier (TSM)

Choose NI Characteristic :Operating Time at PSM = 8.66 @ 1.0 TMS

= (0.14) / ((8.66) 0.02 -1) = 3.17 secDesired Operating Time = 0.4 Sec (Assumed)Desired Time Dial (TMS) = 0.4 / 3.17 = 0.126

Set TMS = 0.13Hence Actual operating Time = 0.13 x 3.17 = 0.41 sec.

RECOMMENDED SETTINGS :

PS = 1.3TMS = 0.13


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OVER CURRENT RELAY SETTING: RELAY R2(51)Plug Setting Multiplier (PSM)

POC of downstream relay R1 = 3900 A @ 0.42 kV= 248.2 A @ 6.6 kV

Hence Plug Setting (PS) = POC / CT PRIMARY= 248.2 / 200 = 1.24

Set PS = 1.3 Actual Primary Operating Current = 1.3 x 200 = 260 A Fault Current = 33805 A @ 0.42 kV

Reflected Fault Current = 2151.2 A @ 6.6 kV Plug Setting Multiplier (PSM) = 2151.2 / 260 = 8.27


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PROTECTION CO-ORDINATION EARTH FAULT RELAY

Criteria for selecting ground fault pick up setting:Selection of plug settings for ground fault relays are not influenced

by equipment rated current / motor starting current. For Solidly Grounded System :

Higher pickup shall be selected to avoid excessive currentthrough the relay.

By adopting higher plug setting, Sensitivity is not sacrificed asfault current is in kAmps. For High resistance Grounded System :

Pick up shall be low enough to obtain desired sensitivity. This istrue as fault current is low. This current further reduces for arcing

faults. To increase sensitivity, sometimes 5A CT connected to 1A relay.


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Ground relay senses only zero sequence currents. Flow of zero sequence currents is very much influenced by

Transformer vector group connections. Example : Fault on star side of delta Star Grounded.Transformer results in flow of zero sequence current on star

side. Hence providing the backup Ground over current relay (say

51N) on delta side of star delta transformer is meaningless. Detection of faults on the Under-grounded systems can only be

done using voltage relays.


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EARTH FAULT RELAY SETTING: RELAY R1(51N)

Set PS = 0.4 A Primary Operating Current = 0.4 x 3000 = 1200 A PSM = 33.8 / 1.2 = 28

Choose Extremely inverse curve (EI) Operating time at PSM = 28, TSM = 1 Operating time = 80 = 0.20 Sec.

20 2 1 Desired operating time = co-ordination margin + relay operation time. Co-ordination margin = (0.4t + 0.15) = 0.154 Desired time = down stream time + margin = 0.01 + 0.154 = 0.164 Time setting multiplier = Desired operation time = 164 = 0.85

operation time at TSM=1 0.2


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EARTH FAULT RELAY SETTING: RELAY R2(50N)Note : Since primary of transformer is delta connected, line to ground fault

current of 400 V will be reflected as line-line fault at 6.6 kV side.Hence set only 50N unit: Primary Protection for 6.6 kV Faults.(1) 6.6 kV system is resistance grounded and the fault current is limited to

100 A.(2) Set PS = 0.1 A(3) Primary operating current = 0.1 x 200 = 20 A(4) Sensitivity = (20 x 100) / 100

= 20% < 30 %(5) Hence set PS = 0.1 A(6) Time Delay = 0.0 sec

Recommended Settings :PS = 0.1 A, Time Delay = 0.0 Sec


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RESTRICTED EARTH FAULT (64R) Normally set at lowest current tap available, say 10% To ensure relay does not operate during external faults, stabilizing resistor

is added in series with the relay. Setting Procedure: The maximum voltage likely to appear across the relay during external

faults is calculated, assuming worst condition i.e. CT on 1 side saturating. VR = I fault (R CT + 2R L)

Where I

fault= Secondary equivalent of fault current. = 33.8/3000 = 11.5 A

R CT = The CT secondary winding resistance. =5 2R L = CT secondary lead resistance. = 2 x 5 = 10

VR = 11.5 (15 ) = 173 V. Next calc. total relay circuit impedance R T; R T =V R / I R =173/11.5 = 15 .

Obtain relay impedance R R from manufacturers catalogue. Stabilizing resistor R S = R T R R .


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Relay 51S : Location : Stand by Earth fault relay of TR C.T.R. = 3000/1 Relay type = SPAJ 115C (SPACOM series ABB make) Earth fault IDMT unit (51N)

Pick up = (0.05 0.4) x In, Step = 0.1 InTime Dial = 0.05-1.00, Step = 0.05

Fault current passing = 33805 A (Earth fault current assumedthrough relay for same as phase fault current)MCC fault.

Set PS at 0.4 A. Chosen characteristic is Normal Inverse (NI)

Operating Time = 2.267 Sec. for PSM = 20.0 & Time Dial = 1.0


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Desired operating time t1:Downstream relay 51N operating Time t = 0.164 Sec.Co-ordination interval td = (0.25t + 0.25) = 0.37 Sec.Desired Operating Time t1 = t + td = 0.164 + 0.37 = 0.534 Sec.

Desired Time Dial TMS :TMS = Desired Operating Time t1 = 0.534 = 0.23

Operating time @ TMS 1.0 2.267

Set Time Dial at 0.25 [Time Dial = 0.05 1.00, Step = 0.05] Operating Time = 0.52 Sec.[2.267 x 0.23]


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Transformer Differential Protection

DIFFERENTIAL PROTECTION.doc
http://mumbaihome/trainingmodules/WIP%20Trg%20Module/Elect/Elect%20Module%20for%20review%20&%20comments/training%20material%20-%20elect-%20vadodara/Relay%20Co%20ordination/DIFFERENTIAL%20PROTECTION.dochttp://mumbaihome/trainingmodules/WIP%20Trg%20Module/Elect/Elect%20Module%20for%20review%20&%20comments/training%20material%20-%20elect-%20vadodara/Relay%20Co%20ordination/DIFFERENTIAL%20PROTECTION.doc


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Relays are installed not to prevent faults, but only to isolate the faultand minimize the damage. Most of the relays act after damage hasoccurred. Sophisticated relays and correct relay setting andcoordination are not a substitute for good maintenance practice.

For successful clearing fault: (1) CT must not be saturated (2) CT & PT polaritymust be correct (3) Integrity of wiring between instrument transformers to relayshould be alright (4) Auxiliary supplies to the relay are available.


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Thank you

Documents

Relay Coordination (1)